Talos Energy Inc.
Q3 2014 Earnings Call Transcript

Published: 5 Nov 2014

[Operator:]

Good morning. My name is Courtney and I will be your conference operator today. At this time, I would like to welcome everyone to the Stone Energy’s Third Quarter 2014 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speaker’s remarks, there will be a question-and-answer session. (Operator Instructions). Thank you. David Welch, Chairman, President and CEO, you may begin your conference.

[David Welch:]

Okay. Thank you, Courtney and welcome once again everyone to our third quarter call. Ken Beer, our Executive Vice President, Chief Financial Officer is joining us this morning and will begin the meeting with our Safe Harbor statement and a review of our financial performance for the quarter as well as updated guidance for the remainder of the year. He’ll then turn it back over to me for some additional comments on the market, our execution and our strategy. Ken?

[Ken Beer:]

Thank you, Dave. Let me start off with the forward-looking statements. In this conference call, we may make forward-looking statements within the meanings of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to all the risks and uncertainties tied to the exploration development production of oil and natural gas. We urge you to read our 2013 Annual Report on Form 10-K and the soon to be filed third quarter 10-Q for discussion of the risks that could cause our actual results to differ materially from those in any forward-looking statements we may make today. In addition in this call, we may refer to financial measures that may be deemed to be non-GAAP financial measures as defined under the Exchange Act. Please refer to the press release or reconciliation of the differences between financial measures and the most directly comparable GAAP financial measures. And with that, we will assume that everyone has seen the press release and the attached financials. Our third quarter adjusted earnings came in at $0.7 million about $0.01 per share, after accounting for non-cash, non-recurring full cost impairment of $47 million. The reported loss was about $29 million. Our discretionary cash flow for the quarter was just over $92 million, about $1.65 per share. Production was above, just above the upper end of our third quarter guidance but oil and particularly natural gas price realizations were weaker than expected which led to our earnings result being slightly below the first call estimates. On the ceiling test impairment was due to several factors including lower oil and gas prices, widening gas – negative gas differentials in Appalachia, produced oil price premiums in the Gulf of Mexico and higher projected future projected transportation processing and gathering expenses. If the prices in differentials continue to stay at depressed levels, we may be subject to another non-cash ceiling test impairment in the fourth quarter but there is no impact on cash flow, but a potential earnings impact. Production for the quarter was just under 40,000 BOE per day or 237 million cubic feet equivalent a day, which was just above the upper end of our third quarter guidance as mentioned. Volumes, from both the Gulf and Mexico and Appalachia were above plans especially as there were no weather related interruptions on schedule if on downtime. Remember we sold our non-core conventional shelf assets in July which was producing 48 million cubic feet equivalent per day. This caused our quarter-over-quarter volumes to decline, although increased Appalachian volumes mitigated the drop to only about 27 million cubic feet a day. Currently we’re now producing in excess of 130 million equivalent per day in Appalachia and over the next two months we’re expected to bring on another 13 or so new wells in our Mary fields which should allow for an exit rate of around 150 million equivalent from Appalachia not for the whole quarter but an exit rate for the year. Additionally, we’re projecting the initial start-up volumes from the Cardona Project later on this quarter, which should also boost the exit rate for the year. So, for the fourth quarter, we would expect to be back up in the 240 million to 264 million cubic equivalents per day range as we add these Appalachian volumes and the Cardona production starts to flow. Also as we look ahead to 2015, with the Cardona oil volumes coming online, we would expect our higher margin oil and NGLs to be over 50% of our volumes. Interestingly when the projected net volumes of about 7,000 BOE per day from the combined Cardona wells come online, we would expect that just the production from these two wells will substantially replace the volumes from the divested non-core shelf properties, and the margins will be significantly higher. So, we continue to execute on our strategy of replacing conventional shelf reserves in production with the longer life Appalachian deep water reserves and production. Regarding pricing, our quarterly oil price realizations are $93.15 per barrel, which is down about $3 from the second quarter. Along with the WTI pricing being down about 13% of our oil volumes came from Appalachia versus just under 10% last quarter, which further pulls down the weighted average oil price. And then obviously, in the fourth quarter, oil price realizations will come down even further as the WTI pricing is in the low 80s and upper 70s, so we would expect that price to be down in the fourth quarter. Our gas price realizations had a significant drop in the second quarter due to both Henry Hub, the Henry Hub benchmark declining and the widening Appalachian differentials during the July through September shoulder months. Obviously, the industry success in the Marcellus in there, Utica has called a regional oversupply situation, although the aggressive response from the midstream and pipeline companies suggest much of the access issues should ease over the next 18 to 24 months. We’ve secured sales arrangements over the next year which provides us with a market for our gas but we are subject to the pricing of the M2 index. As the winter months approach, we would expect to see a seasonal narrowing of the differential to Henry Hub. We also had another adjustment to our gas price realization, due to some accounting complexities, the positive effects of a few of our gas hedges were recorded through the income statement as derivative income of $5.8 million rather than adding to the gas price realization or flowing through other comprehensive income line in the balance sheet. This treatment affected the reported $2.77 realized price by about $700,000 or about $0.06 per mcf for the third quarter, while the remaining $5.1 million was tied to the outer month mark-to-market gains. We expect this treatment to continue in the fourth quarter, again we will receive the same desire to protection of the hedge but we’re recording it through the derivative income line. In the third quarter, our realized NGL prices averaged around $42 per barrel. This incorporates a small under-approved from the low price second quarter, which ended up adding a few dollars to this quarter’s price. Remember the NGL receipts have about – or have a two-month lag, so there is a little more volatility in the price and volumes quarter-to-quarter. Although the recent oil price would decline, would suggest that downward buyers for NGL pricing, we’re also getting closer to the seasonal related up-tick in NGL prices which may provide a little bit of an offset. On the cost side, our LOE dropped to $43 million for the quarter as the sale of a non-core properties reduced our operating expenses. We expect LOE to decrease again in the fourth quarter and reduced our full year LOE guidance to a range of $175 million to $185 million. Remember that even as we add Cardona volumes, and Appalachian volumes, we would expect LOE cost, absolute cost to flatten out which would lead to a reduced LOE per BOE on a unit basis. This is part of the operational leverage at Pompano, at the Pompano platform, whereby additional volumes had very little incremental LOE. And in fact reduces LOE due to the platform PHAPs which we’ll be receiving. The transportation processing and gathering expense was just over $60 million for the quarter, as Appalachian volumes increased. We would expect this figure to increase further in the fourth quarter with this incline in Appalachian production. Our DD&A rate for the quarter was $3.63 or $21.77 per BOE. As expected this unit increase – unit expense dropped from the second quarter figures. And we would expect that DD&A rate to remain within the original guidance range within the fourth quarter as well. Our base G&A before incentive comp came in at just over $60 million for the quarter, flattish with the first and second quarter. Reported interest expense for the quarter was just over $10 million, a slight rise versus the second quarter, due to a lower unevaluated property figure, which determines the amount of interest expense to be capitalized. Also remember that about $4 million that was reported interest expense is non-cash interest tied to the convertible notes accretion. Our total cash interest is still running about $60 per quarter. Regarding taxes, our reported tax rate is now the story due to ceiling test impairment. But we would not expect to pay much of any cash taxes for the year. Our CapEx for the quarter, for the third quarter was approximately $147 million, a little lower than might have been expected. Through the three quarters, our net expenditures are about $655 million. But the fourth quarter will record most of the installation and facilities expenditures at the Cardona project, which will push the CapEx back above the $200 million number. As previously disclosed, our board authorized an increase of our 2014 CapEx budget to $895 million. On June 30, I’ll just remind folks we announced the P&A, our Purchase and Sale Agreement with Talos Energy to sell our non-core shelf assets for $200 million. This transaction was indeed completed in the third quarter at July 31, at an adjusted purchase price of $178 million and allows us to further focus on our core growth areas. At November 3, we had $307 million in cash including $177 million in restricted cash, $178 in restricted cash. Remember that the proceeds from the Talos sale were deposited in a 10/31 account in case we were able to execute on a potential Light-Con exchange acquisition. We do not anticipate that occurring but the funds will much remain in escrow until January 27, 2015 when they will become fully unrestricted. Our $500 million bank facility remains un-drawn except for $21 million analysis so we have plenty of near-term liquidity. We believe this liquidity will fund us well into 2015 and provide the balance sheet strength and flexibility to move us forward with our announced long-term deepwater rig commitment, additional wells at Cardona and accelerated development program at Amethyst and the potential Utica drilling program. We did add a couple of more hedges, 2015 hedges to further protect our cash flow and CapEx program that included the updated hedge position in the press release. I believe that wraps up the financial overview. And with that, I’ll turn it over to Dave for additional comments.

[David Welch:]

Okay, thank you, Ken. Obviously, this fall has been a tumultuous time with crude prices in the near freefall in October and natural gas price differentials expanding rapidly in the shoulder months in Appalachia. This puts a strain on reserves and cash flow as the economic limits rise and individual wells and as we receive lower revenue for any given amount of production. So we’ll have to prudent as we move through this part of the cycle. It helps greatly to have a strong balance sheet and a litany of robust products to execute. Also the facts are that the population of the earth is still rising, driving demand ever higher while at the same time, almost every existing well is either declining now or soon will be. So, we know that investment in quality projects is still needed to deliver enough supply to meet future demand. Our focus is and has been in areas that are believed to be among the lowest unit cost of supply in the non-OPEC world. Specifically for gas that means the Marcellus and Utica and for oil it means deepwater Gulf of Mexico. We expect that the Appalachia differential will close somewhat over the upcoming months and quarters, and we have the luxury of high liquids content in our Marcellus gas to help support the economics of the investment. On the oil side, we’re approximately 50% hedged on 2015 production around $92 a barrel, and have been enjoying about $3 premium for LLS, a Louisiana light sweet over WTI. So, if the oil price were to average $75 or so in 2015, our average realization should still be near our planning price of $85 per barrel. That said, we’ve not yet set our 2015 capital budget but are preparing it now and are reviewing it critically with an eye towards those capital conservations and the preservation of long-term value creation during this phase of uncertainty. Since Ken’s already discussed the ceiling test write-down and the financials, let me focus on execution and strategy. Our production was slightly above the upper end of guidance this quarter due to strong performance from both the Gulf and Appalachia businesses. Our full year guidance is also reaffirmed as we expect to bring on production three more pads in Appalachia, one of which includes our Utica well. And we also expect to bring online our first company operated deepwater subsea tieback Cardona within the next three or four weeks. So we should have an excellent finish to this year. Our Cardona project is a dual flow line subsea development tieback to our 100% owned Pompano platform. We now expect to deliver the project for about $20 million less than budgeted and come online a quarter earlier than projected. We previously guided first production towards the first quarter of 2015, but with the work completed so far, we now expect to come online in the next few weeks. Both of the wells were completed this summer, the Umbilical the flow-lines on the sea floor. The subsea well heads and trees are installed. The jumpers and flying leads are almost all hooked up in the installation vessel, is expected to be released by our construction group around the end of this week. So we’ll soon begin to commission the system and then go through our production startup procedure. We do plan to test each productive interval in both wells and conduct flow rate and pressure build up test on each zone separately to gain valuable reservoir information which will help us optimize reserves and value. We expect to get this testing completed in December, and to be at a full stabilized flow rate by the 1 of the year. But we do expect to have first oil sales in the third and fourth week of November. So it’s an exciting project for our sales, as it’s our first company operated subsea tieback, demonstrates to the market, to our partners and to ourselves that we have the capability to operate successfully in deepwater. We’re on a 65% working interest in the project and expect a gross total production of about 12,000 barrels of oil equivalent per day, when ramped up the full production. The anticipated rate could exceed 50% of our current companywide daily oil production. In addition, since the production handling fees, we’re hearing from processing our partner’s production of slightly higher than the incremental lease operating expense of producing the wells at Pompano, our operating margin is expected to be greater than the price of oil for our Cardona wells. You may recall that the Cardona South well found over 275 feet of net pay in three sand intervals we believe reserves there are large enough to support the drilling of another low-risk development well. We’re also planning a very low-risk offset to the TB9 well which lies between the two wells already drilled. So the Cardona flow line loop was designed and built to accommodate production of these wells. Cardona 4 and 5 are the ones about to come online and the additional wells that Cardona 6 and 7, will be among the first wells drilled with our new deepwater rig. Having the Cardona flow line loop and control system already being in place, will enable us to put these two additional wells on production shortly after drilling and completion. The next Cardona well will likely be drilled in 2015 and could come on production only a month or so after completion. In response to the oil-price pull-back and to conserve capital, we may push back the Amberjack platform development drilling program. We now also expect that the platform, Pompano platform drilling program will at mid-2016 instead of in 2015. These programs have no lease or rig implications so they’re an ideal way for us to flex capital in this uncertain environment. These are still great projects though. And one of the best features of platform drilling is it there is virtually no delay in getting the wells on production once they’re drilled and completed. These were important low-risk wells that help underpin our projected production growth and we look forward to drilling them when the capital and equipment timing is right. Turning to deepwater exploration, the next potential wells to be drilled include Madison and Vernaccia. Both of these Mississippi Canyon near infrastructure and of successful could be tied back relatively quickly. We have 40% interest in the Madison which is operated by Nobel Energy and 31.7% working interest in Vernaccia, which is operated by E&I and with Conoco as our other partner. Our Harrier prospect which is operated by a joint venture partner Conoco is expected to be one of the next wells drilled after the two just mentioned. We currently have a promoter right of 37% working interest and the 20% cost interest. This well is likely to start in the second quarter of 2015. Our deepwater lease base now comprises of 112 blocks, 58 Stone operated blocks and 54 non-operated blocks. We believe that we have ample projects and prospects to utilize the deepwater rig for multiple years and have executed $350,000 a day, 30-month contract for the ENSCO 8503 which has the flexibility to drill any well in our portfolio and which has an excellent record both operationally and safety. In deep gas exploration, we’ve identified a rig to drill two on-shore Louisiana wells. We operate and we’ll likely drill LaMontana prospect in the first half of next year to be followed by the Cayenne prospect later in the year. Again, in the interest of capital vigilance and diversification, we’ve sold down from 100% working interest in LaMontana to 45%. We also have an ideal 50% working interest in Cayenne. Whether these prospects are operated by Stone and are targeting liquids rich gas with reasonable size and relatively low cost on-shore wells. If one or both of these wells are successful, we should have another quick to market source of cash flow. The conventional shelf continues to provide us with important production and cash flow, thanks to an active and very successful work-over schedule this year and despite no drilling. We’ve now completed the sale of our, all of our non-core Gulf Coast properties for just under $300 million in cash and the transfer of about $150 million of liabilities, abandonment liabilities to the purchasers. The final phase of this coring up exercise was the $200 million sale of a mostly gas shelf package to Talos which closed in July. This leaves us with two core oil fields on the shelf, the Ship Shoal 113 unit area and the Main Pass 288 field. We see further development drilling opportunities in each of these areas and may choose to resume those drilling in 2015 depending upon our capital allocation. The Horn Lark prospect in Mississippi, Main Pass 288 could potentially be the first prospect drilled. And for the shelf, it’s a sizable opportunity with a range of 1 million to 7 million barrels. It could be drilled from an existing platform and if successful, it could come online almost immediately. It could also de-risk several other prospects in the field. These two fields are still providing us with over 5,000 barrels of oil equivalent a day and can sustain a worthwhile rate for the next five years. We also retained an option for 50% of the deep rights offshore in case we or someone else finds additional deeper prospects on some of our prior acreage. However, after the non-core property sale, the conventional Gulf Coast now comprises less than 5% of our proved reserves. And we do not consider to, be a growth area. Finally, our last growth area is Appalachia. The Marcellus in West Virginia continues to grow. Our proved liquids rich Marcellus reserves now make up almost half the company’s proved reserves at approximately 0.5 tcf to natural gas equivalents. And our net probably possible and prospective resources or Marcellus could ultimately aggregate over Tcf. Our drilling performance continues to improve as we’re now on pace to drill more than 35 wells this year with our one top-over rig and one horizontal rig program. We’re continuing this dependable predictable program focused in our Mary field in West Virginia, we expect to have another three pads brought on production in the fourth quarter or right at the beginning of the year, which should put our year and exit rate at over $150 million a day. One of the wells to be brought online in the fourth quarter was the Pribble number 6 well which is 3,600-foot lateral Point Pleasant Utica exploratory well. This well which found 120-feet of Point Pleasant intervals has been drilled, completed and hydraulically fractured and is awaiting production facilities to be brought online. The well is expected to be a good one as it has over 5,700 PSI of well-hit pressure with a full column of fluid in the well bore. So the bottom-hole pressure is very high which will drive the gas to the surface and should deliver a good rate. Production in the Point Pleasant has been established on northern, western, eastern and southwestern sides of our acreage. So, a good well test at the Pribble along with the high-rate wells surrounding us should de-risk most of our approximately 30,000 net Utica acres. Even at low natural gas prices, the dry gas Point Pleasant Utica development has believed to be economically viable. And we will likely build a new fit-for-purpose walking rig for delivery of late 2015 to begin a joint Marcellus Utica program on our stack-pay acreage. On our acreage at Mary, the Utica is more than twice as thick and significantly higher pressure than the Marcellus. So we would expect greater gas storage volumes in the reservoir and more energy to push the gas out of the rock, thus higher, significantly higher production rates and recoveries per well than the Marcellus. The range of potential reserves from the Utica could be very impactful for the company, perhaps even single, perhaps single handedly, even doubling or tripling total company reserves eventually. We have sales agreements in place to get all of our gas to the market. Right now, however that market is quite weak and with the large differential from the NYMEX or Henry Hub. There are a couple of remedies for this situation. First there are companies that have too much capacity out of the Appalachian market, and they’re likely to release some of this capacity. And secondly, a lot of new infrastructure was being built. So, we believe this is a temporary situation and that the regional export fees to better markets will come back in line with actual transportation cost over time. Even so, we plan to conserve capital and take a conservative development approach for now, likely share on one horizontal rig between the Marcellus and Utica, until we see evidence that the commodity price situation is being ameliorated. Finally, balance sheet is in excellent shape at the end of the quarter with over $350 million in cash. We also have an underarm credit facility with $481 million available. We feel that we have the financial flexibility to execute our likely to be reduced 2015 capital plan. Our $895 million capital program this year has yielded positive results in light of the success with the drill-bit and the Cardona and Amethyst construction project. Our investment capital is majority weighted toward lower risk development projects and already successfully discovered deepwater reservoirs, platform development drilling at Main Pass 288 Amberjack and Pompano and the Marcellus. Hopefully this group will soon include the Utica and Appalachia. We’re in the final quarter of an exciting and successful year, even though the erratic commodity price market has captured all the headlines and is causing us to make some adjustments going forward. Even with this, we’re still on track to possibly replace the production in reserves sold through our non-core sales in the same year and that was a stretched goal for us internally. In addition to the near term production increases, we have a number of exciting exploration opportunity to execute and we’ll hopefully lead to an over-improving five-year plan. So, with this, we’ll now be happy to take your questions.

[Operator:]

(Operator Instructions). Your first question comes from the line of Michael Glick with Johnson Rice. Your line is open.

[Michael Glick:]

Good morning guys.

[David Welch:]

Good morning, Michael.

[Michael Glick:]

Just looking for some more color on 2015 CapEx in kind of how you think about allocating capital across our portfolio and whether there with the levers to either ratchet down or ratchet up CapEx next year?

[David Welch:]

Yes, Michael we’ve and let Kent comment on this too. But we have put on our five-year plan, a range of $800 million to $1.1 billion. It feels like we’re certainly going to be at the lower end of that, maybe even below the lower end of it, just based on the way things are shaping up right now. There are some levers that could potentially move us up a little bit from the bottom and that would be things like higher sustained production rate from Cardona, a bounce back at gas pricing in the Marcellus, sooner rather than later. There is also, we’ve never joint ventured our Marcellus acreage that’s another lever that could potentially be reviewed. So there are number of things that we could potentially do to access a little bit more capital if we needed. And as far as philosophy and methodology, we try to look at the amount of net present value created per dollar of investment, is one of the criteria. We also look at the proximity of cash flow to the current time. And those are two of the main things that we’ll be looking at as we go through our CapEx procedure for next year. It really begins in earnest next week.

[Michael Glick:]

Okay. And then it looks like the first two wells you will drill with the floater are development wells at Cardona. What are the development costs per BOE associated with those wells? I think it’d be pretty low given the infrastructure already in place?

[David Welch:]

Yes, they should be pretty low given the infrastructure already in place. All we’re going to have to do is just drill the wells and time in. And so, the wells will be drilled from right there on location, you just need to add a jumper and a couple of flying leads and you’d be ready to hook-up. So, there is no real additional infrastructure that’s going to be required Michael, to bring those wells online, just the cost of drilling the wells.

[Michael Glick:]

Okay and just to clarify in terms of your current thinking of 2015 in Appalachia. It sound like the Marcellus will still kind of be the initial focus until late in the year when you do have a new build capable of drilling the Point Pleasant wells?

[David Welch:]

Right. I think, yes, and I think one of the questions we have to answer and we haven’t answered this yet, is do we have a continuous Marcellus development program until that rig comes or do we take a little bit of a gap in the year to conserve capital. So that’s one of the things that we’ll be looking at.

[Michael Glick:]

Okay, got it. All right, I appreciate it.

[David Welch:]

Okay. Ken, anything you want to add on that?

[Ken Beer:]

That’s right on target.

[Operator:]

Your next question comes from the line of Jeffrey Campbell with Three Brothers. Your line is open.

[Jeffrey Campbell:]

Good morning. Actually, just quickly jumping on that last answer that you gave. If the keeping the Marcellus continuous or not is a variable. That almost sounds like that you anticipate that the Utica result is going to produce perhaps the highest return that you got in Appalachia. Is that correct?

[David Welch:]

Well, we think that the Utica has and of course we’ve only drilling exploratory wells, now we haven’t tested it. So, this is a little bit of uncertainty. But the way we’re modeling it now, we think that the Utica, even though it’s dry gas, we’ll have a higher return than the Marcellus on an incremental basis. And part of that is because the Marcellus has already paid for a lot of the infrastructure that we have in place there, so it’s a little bit of an unfair comparison. But on a going forward basis with you’re talking about a well that may cost twice as much as a Marcellus well, but it could have four to six times the rate so, in reserves. So that’s where the Utica gets pretty important.

[Jeffrey Campbell:]

Okay that was good color. I appreciate that. Just real quickly, last quarter you mentioned that there would be some testing on the Tomcat to see if it was essentially a one-well player that might support some additional drilling. Did you arrive at a decision on that?

[David Welch:]

We have not yet. The well is still producing about the same rate, holding up the pressures fairly stable. We need to watch it another couple of quarters before we know if we’re going to do any offset drilling. But we’re a little bit discouraged that early stages and a little bit more encouraged with it now. So we’ll keep you posted on that.

[Jeffrey Campbell:]

Okay. So it sounds like it’s actually declining at a better rate than you anticipated?

[David Welch:]

Yes, it’s sitting there at a stable rate. It’s been producing about 800 barrels a day for quite a while. The pressure on the well head had been dropping and the pressure is now starting to stabilize. So it stabilizes and the rate stays up, that would be a good thing.

[Jeffrey Campbell:]

Okay. And I’ll close with kind of a theoretical question, if the low oil prices persistent in 2015, where do think you would be more likely to add acreage if opportunities emerge? Would it be the Gulf of Mexico or would it be in Appalachia?

[David Welch:]

We probably wouldn’t be in a real high acreage adding mode if these low prices persist for an extended period of time. I think we’ve got enough acreage in the Gulf and in Appalachia to go for a decade or so. And we’re only using up in the deepwater maybe half dozen to a dozen leases a year. We have 120 leases there, so that’s a long inventory. We had believed our Marcellus gave us about eight years of running room and now with the Utica is there, then that stretches you out to a number of years. So, getting additional acreage is not a real necessity for us. Obviously price has declined and the price of acreage starts going down, then we have to look at it as an opportunity.

[Jeffrey Campbell:]

Okay, great. Thank you. And by the way, congratulations on the day rates you secured. I think you guys might have another business laying around there some place forecasting day rates. That was a pretty bold call back at the Investor Day and congratulations.

[David Welch:]

Thank you.

[Ken Beer:]

Thanks.

[Operator:]

Your next question comes from the line of Matt Portillo with TPH. Your line is open.

[Matt Portillo:]

Good morning guys.

[David Welch:]

Good morning.

[Matt Portillo:]

Just a few quick questions. I know that you guys have already gotten quite a few on CapEx for next year. I was curious if you could provide a little more context around how much flexibility? As you look year 2014 program you spent I think around 30% of your budget on exploration and exploration associated spending. Could you talk about some of the flexibility around that spending target and how much that conflicts down over time if you wanted to pull back on the capital?

[David Welch:]

I think we have some pretty good levers to flex. I mean, and some of the bigger things are that we could turn down the Marcellus program for a period of time, okay. We could farm out the ENSCO 5803 for a slot or two if we want chose to. It’s a very competitively priced rig in the market. And we’ve had a number of enquiries already. So that gives us a lever right there. We could also either drill wells and not frac them or we could enter into a joint venture with other parties. So we’ve got a number of levers, we just need to sort through all the details of it and figure out which one is going to be optimal for us preserving as much optionality as we can for the future. Does that help?

[Matt Portillo:]

Perfect. That’s very helpful. And then, I guess just on the leverage side, of things as you guys look out into 2015, could you remind us on where you would like to keep your leverage targets? Just kind of what metrics you are focusing on and how you think about those progressing over the next year or so?

[Ken Beer:]

Yes, Matt, it’s Ken. One of the things we’re looking at is both leverage as well as flexibility and liquidity. As you know our – we’ve got the convertible notes which we’re doing ‘17 but the majority of our debt is really 2022. Our bank facility is un-drawn and I would expect this to start tapping into that facility slightly as we go into 2015. That’s what we do to have some elbow room. Again, we do look at debt to flowing barrel, we look at that EBITDA. There is no single item that dictates where we’ll be. I think we would like to keep our current roughly little over $1 billion of debt pretty much in check as we bring on Cardona production and bring on this additional Appalachian production. So, I wouldn’t look for big flex on the debt side. But it’s one where certainly the bank facility does provide us with that flexibility that we were – that we’ve been keeping in reserve. We still have $300 million of cash and $500 million of bank facility. So we think as we look at 2015, we’ve got some flexibility but to your question, we don’t want to keep pushing the debt side of the envelope. And that’s why as Dave pointed out, we really can both pull back in CapEx, maybe look at potential JV type of instruments. There are some other ways to try to move forward our capital programs, without disrupting the whole – all of the progress that we’ve made in terms of, particularly on the depot or with the portfolio of projects that we have in front of us and the rig commitment that we have for the ENSCO rig.

[Matt Portillo:]

Great. And my last follow-up question here in regards to the Pompano development program and the Amberjack drilling program you mentioned potentially sliding a bit to the right. Is there any color or context you could provide in terms of kind of how much capital we should be thinking about with those two kinds of programs in terms of just moving that capital to 2016 and beyond?

[David Welch:]

Each program is little over $100 million for the full program.

[Matt Portillo:]

Thank you very much.

[Ken Beer:]

And so, as Dave pointed yes, as Dave pointed out that’s obviously, that’s held our production so it’s not like it’s going anywhere. But those platform rigs are also pretty specific and you don’t want to miss a spot when it comes available. I mean, really the dynamic that we have to address or the balance that we have to address is the balance between production projects and then some exploration projects. We don’t want to just hunker down and do no exploration at all for the next 12 or 15 or 18 months. But we’re certainly right, and we recognize it that the platform programs are certainly very attractive. But that’s the balance that we’re trying to work through. And as Dave highlighted over the next couple of weeks, we will be really addressing 2015 and to some extent 2015 and even 2016 as we try to plan through what is clearly lower oil prices and probably lower gas prices.

[Matt Portillo:]

Thank you.

[Operator:]

Your next question comes from the line of Richard Tullis with Capital One. Your line is open.

[Richard Tullis:]

Thanks and good morning everyone.

[Ken Beer:]

Hi Richard.

[David Welch:]

Good morning.

[Richard Tullis:]

Ken, just going back to the deep-water drilling scenario, what’s the estimated current daily all-in cost to drill your Mississippi Canyon area, including the new day rate, the 350,000 a day rate even though that rig doesn’t come available until next year?

[Ken Beer:]

You mean.

[David Welch:]

Let me just jump in for a second here and then Ken can give you the real numbers. But securing the rig, which is typically about half of the thing. But the spread rate is usually $500,000 a day rig has been about $1 million. So, we think that there may be a little bit of potential softness developing in the support area as well. So we haven’t locked into anything yet. But typically we would expect it to be under $1 million a day.

[Richard Tullis:]

Okay, yes.

[Ken Beer:]

Maybe $900,000. In the Cardona, 6 and 7 will be very simple deepwater wells. I mean, I think that our estimated dry hole cost net would be $30 million something – there would be some facility cost as well. So, these are development projects that ultimately are very low cost from a capital standpoint. And importantly they give you almost immediate production and therefore cash flow. So, in terms of self-help, the two Cardona wells could provide a lot of self-help to a certain extent, you have Amethyst which, again will be more of a development project. Yes, it will cost dollars to complete the well and tie back, but it will provide pretty quick production and therefore cash flow. So, those are the type of projects that we have to stare out versus maybe some of our exploration projects that won’t give you that immediate cash flow but you want to try to do early on so you’ll know how to follow-up with the development program if successful. So those are some of the balancing acts that we’re faced with. The two Cardona wells are, it’s hard not to move forward with them because they are low cost, quick wells with cash flow and production associated with them.

[Richard Tullis:]

And then if oil gets to a level or is at a level that you get concerned, one of the first things to go would possibly be that non-op exploration projects you have on the schedule for say over the next one year?

[David Welch:]

I think everything is up for scrutiny. But those are something that we’ll certainly be taking a hard look at.

[Richard Tullis:]

Okay. And then what’s your current gas realizations in Appalachia?

[Ken Beer:]

Well, they’ve gotten slightly better. I don’t want to call victory when you go from differential versus Henry Hub of $2 to now $1.20 or so. But certainly from a seasonal standpoint and they have some winter related bounce back, I think the fourth quarter and the first quarter, I think you’ll see those differentials come in pretty dramatically versus what we saw in the summer months.

[Richard Tullis:]

Okay. What did the pre-drill reserve and cost estimates for the ENI, the Vernaccia?

[Ken Beer:]

That’s – yes, the reserve, the range I think was somewhere kind of P90 of 10/15 and…

[David Welch:]

10 to 100.

[Ken Beer:]

Yes, 10 to 100 is somewhat similar to Madison kind of thing, same type of range.

[Richard Tullis:]

Okay.

[David Welch:]

Good thing about it is it’s one of these four-way closures. And they typically have a low higher success rate than lot of types of pre-ops.

[Richard Tullis:]

Okay. And then Dave what was the pressure readings you gave on the Pribble well?

[David Welch:]

That was about, that has well head pressure of about 5,700 PSI.

[Richard Tullis:]

Okay.

[David Welch:]

Then of course, if you add the weight of the fluid going down to the bottom hole, I think it’s a pretty high pressure gradient at a 0.88 or 0.9. So, that’s a lot of thrust power. So, we’re fairly optimistic about our well although still going to be another three or four weeks before we get a test.

[Richard Tullis:]

Okay. And what was the final cost on that well?

[David Welch:]

I haven’t seen a final cost. But I think it was just under $14 million.

[Richard Tullis:]

Okay, with a good bit of science.

[David Welch:]

Yes, that’s got some science to it. We got, I think we did take a core, the other thing that we’re going to be doing of course is if we get into a pad-mode, where we have a different purpose rig then you don’t have a rig mobilization on every single well. That will save money as well.

[Richard Tullis:]

Okay.

[David Welch:]

We hope to get that cost down to the $12 million or so range. I think it’s kind of an interim target.

[Richard Tullis:]

Okay. And then, just lastly, so, I guess PetroQuest La Cantera project, the production is a little bit less than expected because of ongoing facility work. Do you have that built into your 4Q guidance?

[Ken Beer:]

Yes, Richard. That, you’re correct, that La Cantera is down almost 40% to 50% from its peak. PetroQuest is doing some additional work on the project and we’d look to hopefully get that rate up again. Although I would caution you, I don’t think we would expect it to get back up to that over 100 billion a day growth type rate. But yes, the answer is yes. The range that we have incorporates not only La Cantera but kind of all of our fields we’ve kind of tried to do it somewhat bottoms up.

[Richard Tullis:]

Okay, all right. That’s all from me. Thank you.

[Ken Beer:]

Great, thank you.

[Operator:]

Your next question comes from the line of Doug Dyer with Heartland Advisors. Your line is open.

[Doug Dyer:]

Hi, good morning gentlemen. If you could, could we get a little bit more color on the ceiling test write-down in terms of how much of the reserves are being written down and also if it’s in any particular area that you deem not commercial at this time?

[Ken Beer:]

Yes, Doug, it’s Ken. So, it’s really a multiple of factors. As we mentioned its oil prices coming down, oil price premiums coming down, gas differentials in Appalachia. We increased on a go-forward basis, our guesstimate or estimate on transportation processing and gathering charges. So if you put all that into the pod and you might remember this is all a full-cost pool, you have to go through kind of an accounting, some accounting steps to evaluate and compare your – the present value of your future cash flows that you’re just proved not possible would be proved reserves will throw off. And compare that to your basically some cost, your capitalized cost. And the result in number is somewhere over $1.2 billion to $1.3 billion. On that you have $43 million or $47 million ceiling test write-down because the capitalized, the capitalized portion that NPP&E was just slightly below, I’m sorry was just slightly above the present value of this cash flow. So, it was not one area or one issue, it was really the combination of a lot of – or those three or four different items.

[Doug Dyer:]

Okay. And also I believe you said you’re 50% hedged with oil for 2015. What was that price again please?

[David Welch:]

Yes, I think it’s somewhere around 92.

[Ken Beer:]

92 some change.

[Doug Dyer:]

All right, thank you.

[Ken Beer:]

Great. Thank you, Doug.

[Operator:]

Your next question comes from the line of Vans Shaw with Credit Suisse. Your line is open.

[Vans Shaw:]

Hi, yes, good morning. I just wanted to ask you guys if you could refresh me what percentage of your real production is coming from the deepwater Gulf, what percentage from on-shore and what percentage from the shelf stock?

[Ken Beer:]

This is Ken. I will do some eyeballing here. And you probably have and maybe I would just separate it into Appalachia and then really combine deepwater gas together and shelf. So, on the oil side, you have Appalachia, I think I’ve mentioned it before is about 13%. The remainder would be deepwater, kind of split 50-50 between deepwater and the shelf. Gas volumes now Appalachia is probably approaching 60% of our gas volumes with really deep gas, deepwater and the shelf kind of it at roughly 10% or 15% are little, each about 13% to 14% of the gas volumes. And then NGL volumes Appalachia is about 75% of the NGL volumes. So that gives you at least the sense, kind of byproduct where the volumes are coming from.

[Vans Shaw:]

Yes. So, I mean, also from your earlier comments you’re saying, main past 288 and ship shell 113 are pretty valuable situations for you producing oil and you can drill more platforms?

[David Welch:]

That’s right. They’re almost 5,000 or 6,000 barrels a day of oil.

[Vans Shaw:]

Got you. So, that’s interesting. Thank you very much. I appreciate it.

[Ken Beer:]

Thank you.

[Operator:]

Your next question comes from the line of Andy Peterson with Simmons & Company. Your line is open.

[Andy Peterson:]

Hi guys, good morning. Can you talk a little bit about the rig flexibility in the Marcellus and Utica? If it comes to it could you guys drop that rig or what’s the contract on that?

[David Welch:]

I think the contract expires at the end of this year. So, we have the potential to either pop it or extend it at that time.

[Andy Peterson:]

Okay. Perfect, and then also just looking out at late 2015 with the Cardona 6 and Cardona 7. Is that – do you guys think that’s something that you would go ahead and drill in any sort of commodity environment just to increase reserves that have already been discovered? Or how should we think about the deepwater portfolio?

[David Welch:]

Yes, I think in the – Ken can give you his thoughts on that too. But I think we probably would drill those wells. There are, their high return, high rate of return and the production comes on almost immediately which provides cash flow. And that’s two of the main criteria that we’re looking for. The infrastructure essentially is almost already been paid for by the Cardona 4 and 5 wells. So, and essentially getting a free ride there with them. And that’s what makes them so attractive.

[Ken Beer:]

Yes, Andy. Those projects you can probably go down to well below $30 to $40 and they still will have a return associated with them as they point out as virtually, there is basically no LOE associated with it because the platform fees that are tied to it. And the platform itself, it’s all rough, mostly for the most part fixed cost. So, it’s hard to see why we wouldn’t move forward. Although your point is appropriate in that. At some point, you don’t want to produce into exceptionally low oil prices. But at $70 or $80, you still have excellent economics on those two projects.

[Andy Peterson:]

Perfect. That makes sense. Thanks guys.

[Operator:]

You have a follow-up question from the line of Jeffrey Campbell with Tuohy Brothers. Your line is open.

[Jeffrey Campbell:]

Hi, and thanks for taking the question. I just wanted to make sure that I understood one part of the discussion with regard to the ceiling test. Because you said that you were anticipating higher transportation costs. But at the same time, we earlier had discussed the possibility of picking up some favorable transportation in Appalachia as some guys like say maybe WPX or some of the other guys that are kind of pulling back and have a lot of extra transportation. So maybe some of that could be obtained as the favorable price. Can you just kind of help me understand?

[David Welch:]

None of that’s factored in.

[Ken Beer:]

Yes, and also on the transportation side, you do have quarter-to-quarter you make some of these adjustments. So as it gets more favorable that actually would provide some positive for us. But we do try to look at it quarter-to-quarter. That’s just – that’s the process that we utilize. But to your point, yes, it could provide some help going forward. But it’s, again, these are not huge numbers rather more on the margin providing with – this quarter was a small ceiling test hit. Certainly, if gas prices particularly remained very low and the differential remains high relative to the Henry Hub, that’s probably a bigger fear that I have in terms of ceiling test issue versus the transportation process and then gatherings on.

[Jeffrey Campbell:]

Okay, good. Thanks, I appreciate that.

[Ken Beer:]

Okay.

[Operator:]

There are no further questions at this time. I will turn the call back over to the presenters.

[David Welch:]

Okay. Thanks everyone. We appreciate you being on the call this morning. And hopefully we’ll be talking to you soon. Thanks a lot. Bye.

[Ken Beer:]

Thanks.

[Operator:]

This concludes today’s conference call. You may now disconnect.